Vertical seismic profiling method utilizing seismic communication and synchronization

ABSTRACT

A while-drilling Vertical Seismic Profiling (VSP) data acquisition system utilizing the same seismic shots for three purposes is disclosed. First, the seismic shots provide a means for synchronizing a downhole clock in the VSP receiver to a master clock at the surface, thereby enabling correct determination of seismic travel times. Second, the same seismic shots are also used to communicate commands and other information to the downhole VSP receiver, such commands controlling the actions of the VSP receiver or associated devices. Third, the same seismic shots are utilized for purposes of the VSP survey itself, i.e. determination of seismic travel times, forming of seismic images, and determination of geologic and formation fluid properties using the VSP methods.

CROSS-REFERENCE TO RELATED APPLICATIONS

THIS Application claims the benefit of U.S. Provisional Application No.60/660,026 Filed Mar. 9, 2005.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to novel while-drilling. Vertical SeismicProfiling (VSP) methods and equipment. One aspect of the inventionpertains to measuring and correcting the drift of a downhole clockassociated with the VSP receiver in the borehole. Another aspect relatesto communication from the surface to while-drilling logging tools in aborehole and to the control of these tools by commands and informationsent from the surface by seismic signals and/or by special utilizationof surface controllable drilling processes.

2. Description of Related Art

Those in the petroleum industry are increasingly concerned with‘logging-while-drilling’ (LWD) or ‘measuring-while-drilling’ (MWD)methods that allow early access to information about the geologic andfluid conditions surrounding the borehole as the drilling progresses andduring extraction of the drill string from the hole. The LWD and MWDmethods are collectively referred to as ‘while-drilling’ methods in thisspecification. Knowing such information while the drilling process isactively progressing allows decisions to be made that may have a verylarge impact in terms of attainment of project objectives includingpetroleum productivity and constraint of project cost. Vertical seismicprofiling (VSP) methods have, in the past, been only practicable afterthe drill string was extracted from the borehole. More recent technologyhas, to some degree, obviated this requirement. The introduction ofseveral new methods has made it possible to acquire VSP surveys asdrilling progresses. However, these new methods have suffered fromlimitations. One important limitation is the lack of sufficientlyaccurate time-keeping in the downhole tool: as the downhole clock driftsrelative to the master clock at the surface, error accumulates in theseismic travel time measurements that can be very detrimental to the VSPprocessing and resultant geologic information. Typically, prior artmethods have been limited to time-keeping within about 2 milliseconds oftrue time. VSP surveys could provide significantly better results iftime-keeping could be within ½ milliseconds of true time.

The rotation of the drill bit creates seismic energy that can beutilized as a means of illuminating the subsurface geology. If recordedat the surface of the earth, drill bit energy may provide VSP surveyinformation. However this technique does not always work effectively.For example, when drilling soft formations insufficient seismic energyfor imaging may be transferred to the in situ formation. Other methodsthat utilize a surface seismic source combined with seismic receivers ina tool located near to the drill bit in the drill string have beendevised and are used. Such methods are designated as ‘while-drilling VSPmethods’ in this document. These “while-drilling VSP methods” in thegeneral case and as defined in this specification, may include methodsthat are applied during pauses in actual drilling and also during pausesin the process of extraction of the drill string or re-insertion of thedrill string into the borehole, as is required for replacing drill bitsor other reasons.

The seismic receiver package (called VSP receiver hereafter)incorporates seismic and other sensors combined with processing meansand is capable of acquiring the VSP seismic data during periods whendrilling motion, drilling fluid flow and attendant seismic noise havetemporarily abated. The VSP receiver is normally battery powered and isnot connected to the surface by wire or fiber conductors that mightprovide communication to or from the surface.

Complex control signals could readily be conducted to the seismicreceiver from the surface by electrical wire or fiber optic link ifeither were available. However, when a drilling operation is underway itis inconvenient or impractical to provide these physical linkages fromthe surface to devices deep in the borehole via the drill string.

Other methods have also been sought to transmit control signals to suchdownhole devices. Electromagnetic communication through the earthbetween the surface and locations in a borehole has been utilized by themining and petroleum industries. However, this method is subject tolimitations imposed by highly-resistive rock formations and by deepboreholes. Electromagnetic wave signal strength is weakened as formationresistivity in the intervening earth increases. Electromagnetic noisemay also prevent successful communication. Hardware in the wellbore suchas surface casing and the drill string may interfere with signalreception. Deep boreholes imply high temperature and high pressureconditions, as well as requiring longer signal transmission distancesand are not amenable to the application of existing electromagneticcommunication systems.

Because of the paucity of opportunity to communicate to the downholeseismic receiver package in prior art while-drilling VSP systems, theseismic receivers have been designed and programmed to operateautonomously, without control by a surface operator for extended periodswhile downhole. A capability for selective transmission of limitedamounts of data (such as observed seismic travel time) from the seismicreceiver to the surface via the borehole can be pre-programmed, thecorresponding software loaded into a tool at the surface and implementedusing an uphole signaling means. One such uphole, signaling means iscalled mud pulse telemetry and utilizes pressure pulses in thecirculating borehole fluid (drilling mud) generated by a signalgenerator device near the drill bit called a mud siren. In conjunctionwith mud pulse telemetry or other uphole signaling means, adata-on-demand process would be invaluable in that vitally needed datacould be requested at any time, but this capability would require ameans of sending a command to the mud pulse signal generator tool viathe seismic receiver package or dynamically controlling it in some otherway.

It would be advantageous to be able to have at least a limitedcommunication with the VSP receiver from the surface while conducting asimultaneous drilling and VSP data acquisition project so that the VSPreceiver's operation could be altered in light of new information, suchas might be gleaned from the seismic travel times transmitted using mudpulse telemetry. Other LWD and MWD systems also could benefit from sucha capability to alter their operations upon demand as drillingprogresses. Preferably, the entire drilling and concurrent loggingprocess could be made an adaptive instead of simply a pre-plannedoperation that is unable to respond to unanticipated drilling conditionsand changes in the geologic and fluid models based upon new knowledgegained while drilling. The reward would be in terms of increasedprobability of drilling success and significantly greater economicreturn.

As mentioned in the opening paragraph of this section, a synchronizationproblem has limited the effectiveness and value of VSP surveys conductedwith the VSP receiver incommunicado with the surface (except for limiteduphole communication via mud pulse telemetry). In seismic imaging andseismic velocity field determination, it is desirable to know seismictravel times to at least the nearest millisecond and preferably to thenearest ½ millisecond. This level of travel time precision necessitatesprovision of a precision clock as a component of the downhole seismicreceiver package. A pre-mission synchronization of the downhole clockwith the master clock at the surface ensures that both clocks commencethe VSP data acquisition mission in exact agreement as to current time.A post mission re-synchronization allows measurement of total clockdrift during the downhole episode and estimates of drift at intermediatetimes can be interpolated; however this is not sufficiently accurate asthe drift rate may not have held constant throughout the downholemission. The surface clock may be an extremely precise clock becausethere is no effective limitation on power, cost or physical packaging ofthe clock, and furthermore it may be periodically updated with othermore precise time references such as GPS time. However the downholeclock has limitations imposed because of the environment in which itmust operate. Extremes of pressure and temperature in which it mustcontinue to operate with high precision, physical constraints of thedeep borehole environment, along with a potentially limited power budgetfor lengthy downhole missions, have mandated that a clock with lessprecision than desired must be chosen. While a precision of 10 to theminus 8^(th) power would be considered sufficiently precise for mostapplications it is not sufficiently precise for the VSP applicationbecause it would mean that an error of 1 millisecond could build up in28 hours. For VSP, the downhole clock needs to be within ½ millisecondof the master clock at all times during the survey and the clock mayneed to operate downhole for a period of several days or more.

Several prior art methods of synchronizing a downhole VSP clock to asurface clock have been disclosed to utilize sonic signals travelingalong a borehole. VSP tools as described in U.S. Pat. No. 5,555,220, orin EP 01464991A(A1), or in WO 00/13043 or in U.S. Pat. No. 6,308,137have an unfulfilled need for highly accurate synchronization (½millisecond) of the downhole clock (associated with the downhole seismicreceiver) to the surface clock (associated with the seismic source andsurface seismic receiver).

U.S. Pat. No. 6,424,595 describes a synchronization method having a“pinger” at the borehole wellhead transmitting signal pulses along adrilling mud column to a downhole “pinger receiver”. Although the '595procedure accomplishes synchronization, it suffers from precisionproblems (2 msec) and requires additional equipment (the pinger andpinger-receiver at the surface and downhole). The pinger may not providesufficient signal strength to allow detection of the reflected pulse andmay risk damage to the pipe near the well head that is pinged. Resultsare not available until the tool is retrieved whereas it is useful anddesirable to know the one-way seismic travel time as drillingprogresses.

The disclosure of WO 00/13043 describes a method of clocksynchronization that includes the transmission of acoustic pulses down apipe within a wellbore at predetermined times, can also send the currentposition in the hole to the downhole receiver with acoustic signals, andis able to perform synchronization at the receiver using this approach.Limitations of this solution are accuracy of the acoustic travel timeassumption, ability to receive the acoustic signals at significant depthand requirement for the acoustic system (additional equipment andoperational considerations).

U.S. Pat. No. 6,308,137 describes a method of seismic signalcommunication with a downhole well tool. Although the U.S. Pat. No.6,308,137 disclosure relies upon a high precision downhole clocksynchronized to a surface clock, the description includes noaccommodation for drift from synchronization.

U.S. Pat. No. 6,002,640 discloses a method of synchronizing a firstclock that is associated with a surface positioned seismic receiver to asecond clock that is associated with a surface positioned seismic sourcewith the notation that either the receiver or the source may be downholeor in a mine. U.S. Pat. No. 6,584,406 claims an identical method ofsynchronization but as applied to the case of a downhole seismicreceiver associated with a controllable tool. Neither of these twopatents specifically describes application of the synchronization methodto VSP data acquisition. However, the provisional patent applicationassociated with U.S. 6,002,640 states that the method of the inventioncan be applied to VSP.

The VSP receiver could also be controlled from the surface, using themethods of these same two patents, to improve its operationalperformance and capabilities. The same seismic signals could be used tosimultaneously control as well as to synchronize the tool. Moreover,these same seismic signals constitute the data that serve the objectiveof the VSP survey by providing the sought information relevant to thegeologic conditions around the borehole. No other method has heretoforebeen described or patented that can with the very same seismic shotsperform these three functions: (1) synchronization of receiver with theseismic source, (2) control of the processes in the seismic receiver andconnected tools, and (3) provision of seismic data for the VSP traveltime and imaging calculations.

Other MWD tools in proximity to the seismic receiver can also beadvantageously controlled by the seismic signals, using the same methodsas for control of the VSP receiver. The shots used for control ofauxiliary tools may also have the multiple uses described above, i.e.they can also be used at the same time for synchronization of thedownhole clock and provision of seismic data for the VSP purposes.

Thus there is a need in the petroleum extraction industry for a methodthat could overcome the deficiencies of currently availablewhile-drilling vertical seismic profiling systems. This method couldprovide re-synchronization of the downhole clock while the drill stringis in the hole, while simultaneously exercising a wide range of controlcommands and parameter settings for the downhole VSP receiver and alsoassociated while-drilling logging tools, and would be efficient as wellas very reliable. This ideal while-drilling VSP method could alsoprovide information such as seismic travel times, clock drift and anindication of whether a command was received downhole by upholesignaling utilizing mud pulse telemetry or other means.

Certain terms are used in this specification that conform to industryvernacular but require definitions to ensure unambiguous communication.These terms are defined as follows:

-   SHOT: means a “seismic shot”; used interchangeably with “seismic    shot”.-   SEISMIC SHOT: defined as (1) the deliberate act of creating seismic    energy by a controlled seismic source at a source location in or on    the earth; and (2) also is used to refer to the manifestations of    that seismic energy as may be received and recorded at various    locations away from the site of origin. For example, a “shot” may    mean the received and digitized wave energy of the seismic shot as    in “the shot was processed by cross-correlating with a prior shot.”-   SHOT TIME or SHOT INITIATION TIME or INITIATION TIME: defined as the    time of initiation of the earliest seismic energy of the seismic    shot at the point of origin.-   SEISMIC TRAVEL TIME or TRAVEL TIME: the time period from the shot    initiation time to the time of arrival of the first seismic energy    at the VSP receiver in the borehole.-   SEISMIC SOURCE: refers to the mechanism for creation of the seismic    energy. There are two classes of seismic sources, (1) those that are    impulsive sources, meaning that substantially all of the energy is    initiated in a very short time window, e.g. less than 300    milliseconds, and (2) those that are non-impulsive. The impulsive    seismic sources are exemplified by explosive sources and by an    airgun source. The non-impulsive sources are typified by the    vibratory sources (called Vibroseis in the industry) that create    seismic energy continuously over a time period that is typically 5    to 50 seconds in duration. In this document a shot can be initiated    by either an impulsive source or a non-impulsive source.-   SHOT POINT: is the term used to denote the position of the seismic    source when a seismic shot occurs.-   FIXED SITE: an area of limited size in which one or more repeatable    seismic sources can be located.-   REPEATABLE SEISMIC SOURCE: A seismic source that

A. can be activated to transmit a seismic wave form into the earth orinto the water layer near the surface of the earth, and

-   B. can be re-activated again and again, after brief interludes of a    few seconds duration, to transmit the same or substantially the same    waveform, and-   C. whereby the location of the seismic source for the initial    activation and for each subsequent activation is substantially the    same so that-   D. the seismic wave profile from all of the nearly identical    transmissions will be nearly identical when observed under    sufficiently low ambient noise conditions at a point arbitrarily    positioned on or in the earth in proximity to the seismic source.-   SUBSTANTIALLY REPEATABLE SEISMIC SOURCE: A repeatable seismic source    that achieves nearly identical wave profiles under given conditions    wherein cross-correlation coefficients exceed 0.7 and standard    deviation of cross-correlation peak times is less than 5    milliseconds.

SUMMARY OF THE INVENTION

A preferred embodiment of the invention is a while-drilling VSP systemsuitable to utilize seismic energy generated by a surface source to(1)communicate information Lo a VSP receiver located near to the drillbit while the same seismic energy (in the form of seismic shots orpulses) provides (2) a re-synchronization means to correct the downholeclock associated with the VSP receiver to the master clock at thesurface and also provides in the same shots (3) seismic data requiredfor the VSP survey. The VSP receiver contains a processor that may alsobe linked to other while-drilling logging tools or othercontrollable-devices near the drill bit so that commands can betransmitted from the surface and conveyed via the VSP receiver'sprocessor to the associated tools. The associated tools if suitablyconfigured can thus alter their operations in response to instructionstransmitted via seismic signals from the surface.

Repeated seismic shots generated from the same surface location near theborehole are a normal requirement in prior art VSP surveys. Therepetition of shots provides an opportunity for measurement of drift ofthe downhole clock associated with the seismic receiver package and alsofor communication of instructions or other information to the seismicreceiver's processor. Seismic shots are initiated at certain selectedpre-determined times known as times of potential shots to the downholeprocessor. Shots will normally be taken only when active drilling andpumping of drilling fluid has ceased, for example such as occurs duringthe addition or removal of a drill pipe section or when drilling isdeliberately paused at a point in the geologic section of particularinterest.

Communication protocols may be based on deliberately imposed time delaysof shots and/or a binary shot/no-shot coding. The binary method caninclude a coding in which the number of consecutive shots takensignifies the communicated information.

Cross-correlation is applied to recorded data using a reference functionthat may be formed by combining other potential or known shots from thesame or an adjacent receiver position and initiated from the same sourcelocation. The cross-correlation is analyzed to determinepresence/absence of signal from the potential shot and to measure anytime delay used for communication. A best rendition of the seismicsignal for the current receiver location is formed by combining thedetected shots for the location. Iterations of cross-correlation andreference-forming may be applied yielding successively more accurate andnoise-free estimates of travel time and deliberately imposed delays aswell as improved representations of seismic energy for VSP analysis.

Other means may be utilized to augment the seismic shot communication.The drill string may be rotated in a special on/off sequence or pumpingof borehole fluid may be turned off and on in a predetermined sequence.These augmentary methods are very much poorer in signal bandwidthcompared to seismic but can be useful for sending simple messages underhigh ambient noise and weak seismic signal conditions. The augmentarymethods may be used separately or in combination with each other andwith the seismic shots.

The subsurface sensors may include a small array of geophones,hydrophones or other motion or pressure sensors, and are both for theprimary purpose of receiving seismic waves from the surface shots andfor a secondary purpose: to determine periods of quiet when noise levelsfall below a threshold level. The threshold level may be pre-set,communicated from the surface during the mission, or dynamically setaccording to a downhole process. The seismic receiver is programmed toknow that shots will not be taken at the pre-determined times ifdrilling or pumping is underway. Thus power conservation andconservation of computer resources may be realized by not recording andby limiting the processing under high noise conditions. A further meansof resource conservation may be implemented in which temperature andpressure sensors are also included in the VSP receiver tool and the VSPreceiver may be programmed to not attempt to receive seismic data untilpre-programmed temperature and pressure conditions are met.

The downhole processor may be linked to controllers of otherwhile-drilling logging tools so that instructions and other information,conveyed via seismic shots or the augmentary signaling means to thedownhole processor, may be relayed to them; and so that they may sendinformation back to the downhole processor for its possible action.

Calculations of downhole clock drift may be made after the re-occupationof any previously-seismically-surveyed position in the borehole. Thesecalculations may be made while the mission is in progress, for exampleby re-shooting selected receiver positions as the drill string iswithdrawn from the hole for a bit change, or after the bit change as thedrill string is extended downward through the prior-surveyed borehole.The drift calculations may be made in the downhole processor; or at thesurface if seismic travel times have been transmitted uphole by mudpulse telemetry or other signaling means. Or they may be made after theseismic receiver has been returned to the surface and its informationtransferred to the surface seismic controller computer. The downholeclock may be re-synchronized to the uphole or master clock at thecommencement, during the downhole mission and after its termination; theseismic travel time estimates may be corrected for drift of the downholeclock during the downhole mission and/or after the return of the VSPreceiver to the surface. Selected information from the VSP surveyprocessing performed downhole and other information is transmitted tothe surface by use of mud pulse telemetry or other available upholesignaling means.

BRIEF DESCRIPTION OF THE DRAWINGS

Other features and advantages of the invention will be recognized andunderstood by those of skill in the art from reading the followingdescription of the preferred embodiments and referring to theaccompanying drawings wherein like reference characters designate likeor similar elements throughout the several figures of the drawings.

FIG. 1 is a schematic profile view of a rock formation showing aborehole, while drilling is in progress, depicting seismic andassociated system elements.

FIG. 2 is a view of the portion of the preferred embodiment at or nearthe earth's surface.

FIG. 3 is a view of the while-drilling VSP seismic receiver tool 150positioned in proximity to the telemetry transmitter 140 deep in theborehole.

FIG. 4 is a schematic view of the seismic sensor system 330.

FIG. 5 is a schematic view of the signal processor 340.

FIG. 6 is a schematic view of the power supply 345.

FIG. 7 is a schematic view of the process controller 350.

FIG. 8 is a schematic diagram of a controllable while-drilling non-VSPtool 185.

FIG. 9 is a process flowchart of a preferred method of while-drillingVSP, during the downward drilling phase, that results in the initialmeasurements of the seismic travel times and actuation of downholecontrollable devices.

FIG. 10 is a process flowchart continuing after FIG. 9 that shows thepreferred method of while-drilling VSP, during the re-occupation of aposition previously seismically surveyed, that results in the subsequentmeasurements of the seismic travel times, estimation of downhole clockdrift, and actuation of downhole controllable tools.

FIG. 11 is a process flow chart continuing after FIG. 10 showing thepreferred method of while-drilling VSP, during the stage of extendingthe drilling string assembly downward through previously shot boreholeand re-synchronizing the downhole clock prior to resumption of actualdrilling.

FIG. 12 is a process flow chart showing the process of hybridcommunication combining seismic communication with communication bymanipulation of the surface controllable drilling processes.

FIGS. 13A and 13B illustrate the comparison of received seismicwaveforms using the enhanced seismic shot signal estimate and thecross-correlation process.

FIG. 14 illustrates TABLE 1 which depicts a project menu according tothe preferred embodiment providing for communication with a VSPwhile-drilling tool, linked to other controllable tools, and utilizingbinary seismic signals only.

FIG. 15 illustrates TABLE 2 as an example of the application of theproject menu from TABLE 1 to message transmission and reception.

FIG. 16 illustrates TABLE 3 which depicts a similar project menu to thatof TABLE 1, but adds utilization of time-shift signaling to augment thebinary seismic signaling, so as to enable the efficient communication ofnumerical parameters such as current VSP tool position in the borehole.

FIG. 17 illustrates TABLE 4 as an example of the application of theproject-menu from TABLE 3 to message transmission and reception.

FIG. 18 illustrates TABLE 5 as a project menu according to the preferredembodiment providing for communication with a VSP while-drilling tool,linked to other controllable tools, and utilizing binary seismic signalstogether with activation and pausing of drill bit rotation tocommunicate to the tool.

FIG. 19 illustrates TABLE 6 as an example of the application of theproject menu from TABLE 5 to message transmission and reception.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring to FIG. 1, a borehole 180 contains a drilling string assembly190 connected to a wellhead equipment ensemble 130. A controllablewhile-drilling VSP seismic receiver/processor tool 150 (called VSPreceiver in this document) is located deep in the borehole 180 at thelower end of the drilling string assembly 190. At the or near theearth's surface 105, a repeatable seismic source system 110 (calledseismic source hereafter) is located at a fixed site 100. Seismic source110 generates seismic signals 160 in response to commands from a VSPsystem controller 120. Seismic sensor system 115 monitors the seismicsignals 160 and any seismic emanations from the vicinity of theborehole.

VSP system controller 120 provides an operable interface between theseismic source 110 and a surface operator. In the preferred embodiment,the VSP system controller accepts commands from the operator such as bya keyboard or data entry link. The VSP system controller then executesthe commands according to pre-programmed instructions or menus, andtransmits coded signals to the seismic signal source 110 over anyappropriate communication link, causing it to activate periodically toproduce a desired sequence of seismic shots (see definition of a seismicshot). VSP system controller 120 may be a stand alone assembly or may bein continual communication with another device or system, such as a wellmaster system controller 125 that controls other equipment andsubsystems of the wellhead equipment ensemble 130.

Seismic source 110 comprises one or more of any substantially repeatablevibratory or impulsive controllable seismic signal generators such asare commonly used in Vertical Seismic Profiling (VSP) applications inthe petroleum industry. As such, the seismic source 110 is capable ofgenerating a series of identical or substantially identical sourcesignals 160. Suitable seismic frequencies are those less than about 500Hz, but it is envisioned that frequencies on the order of 8-150 Hz willbe most appropriate. A number of suitable seismic sources are availablein the industry for the application. Modern Vibroseis sources are idealfor this application and are highly repeatable and controllable towithin 250 microseconds. Other suitable sources may include impulsivesources such as the land or marine airgun systems.

Fixed site 100 is an area of limited size in which one or morerepeatable seismic sources can be located while maintaining theoperation of seismic shot synchronization/communication, as disclosedbelow. Multiple sources-may be shot simultaneously to increase signalstrength. The precise size of the fixed site may vary somewhat, but isconstrained by the general requirement of quality assurance, and thedifferences created in the transmitted seismic signals by significantmovement of the source location. A dynamically positioned seismic sourcewith limited variation in location may be most suitable for marineapplications, for example. Reasonable testing will provide a guide toappropriate dimensions for the outer boundaries of the fixed site.

More than one fixed site may be utilized in a given project associatedwith one borehole 180. This is required in the case of a ‘walk-away’ or‘walk-above’ VSP survey. Multiple boreholes 180 may also be utilized toreceive any seismic shots so generated, if each is equipped as shown inFIG. 1. The fixed site 100 and seismic source 110, instead of being ator near the earth's surface, may alternatively positioned in theborehole 180 or in a different borehole in the vicinity.

The seismic signals 160 generated by the seismic source 110 aremonitored for quality assurance using one or more seismic sensor arrays115 placed at or near the earth surface or in a borehole. It isenvisioned that seismic sensor array 115 will be located on the order ofa few hundred feet from the seismic source 110, although this distanceis not crucial to the invention. Appropriate seismic sensors includegeophones, hydrophones, and a combination of geophones and hydrophones.Seismic sensor array 115 preferably has a communication link to both theseismic source 110 and system controller 120. Recording of signals fromseismic sensor array 115 and their analysis is accomplished by systemcontroller 120. Appropriate communication links include radio, wire andfiber optic.

The nearly identical seismic signals 160 (from each shot of the series)each traverse the lithology around the wellbore in an identical mannerto arrive at the VSP receiver 150 by myriad direct and indirect paths.By arrival time, each seismic signal has been naturally altered bynoise, multiple reflection, attenuation, and other factors. Thus, uponarrival the seismic signal may have a longer signal profile as depictedby received seismic signal 170.

The VSP receiver 150 in the borehole 180 is controlled by pre-loadedinstructions and by instructions conveyed to it via seismic signals 170and/or via other signals generated by surface-controlled operation ofthe drilling and pumping processes of the drilling rig. The controllablewhile-drilling non-VSP tool 185 (called controllable tool in thisdocument) is in physically proximity and in direct communication withthe VSP receiver 150. This tool may be, for example, an acoustic logging(while-drilling) tool. It may, in different example, be a controllabletool that is not a logging tool. A controllable downhole while-drillingsignal transmission device 140 (called a telemetry transmitter in thisdocument) such as a mud-pulse signal generator is in directcommunication with and is controlled by the VSP receiver 150. Theafore-mentioned devices 150,185 and 140 are configured as the lower partof the drilling string assembly 190. The drill bit assembly 195 islocated at the deepest position of the drilling string assembly andcreates new borehole as it is rotated. Rotation of the drill bit andpumping of borehole fluids is controlled by the surface operator.Pumping causes circulation of the borehole fluids, such as drilling mud,downward through the drilling string assembly and upward between thisassembly and the borehole wall.

As explained below, a series of the nearly-identical seismic signals 160are used to control and synchronize the VSP receiver 150. The VSPreceiver receives all of the communications from the surface whether inthe form of seismic signals of in the form of signals sent bymanipulation of the drilling operations such as rotation of the bit orpumping of borehole fluid. It detects, records, processes and analyzesthese signals. The analysis yields an interpreted message in the form ofinstructions or other information which the VSP receiver either actsupon to control its own processes or further transmits to other downholecontrollable devices such as controllable tool 185 and telemetrytransmitter 140. Any while-drilling downhole devices capable ofperforming a controllable action or series of actions that can provide adesired result are possible controllable devices in the preferredembodiment of this invention.

The received seismic signals 170 first serve the purpose ofcommunication from the surface to the VSP receiver 150 as describedherein, but also serve a second very important purpose, that offacilitating precise and accurate time-keeping in the VSP receiver 150,and this is crucial to success of the VSP survey itself. A clock in theVSP receiver may be periodically re-synchronized to a surface clock thatcontrols timing of seismic shots and this allows correct determinationof seismic travel times to within ½ millisecond or better. The method bywhich this is accomplished is explained in detail later in thisdescription of the preferred embodiment.

A third purpose of the seismic signals 170 is to provide the basicseismic data that are the essence of the VSP survey itself. Theseseismic signals are recorded, processed and analyzed to provide theseismic images, seismic velocity model, derived geologic models andinterpretations that are the primary objective of the VSP survey method.Because these important results are available in timely fashion duringthe drilling phase their value is increased many-fold over that oftraditional post-drilling VSP surveys.

Referring now to FIG. 2, the repeatable seismic source system 110includes a source control processor 230 and a seismic signal generator250. VSP system controller 120 includes system controller computer 280,master clock 285, and system controller power supply 290. Communicationlink 270 extends between seismic source 110 and VSP system controller120. Seismic sensor array 115 is also shown.

VSP system controller 120 accepts instructions from the human operatorby, for example, a keyboard or mouse. Alternatively, a computer or otherdevice may provide instructions to VSP system controller 120 directly.The system controller computer 280 translates these instructions into acoded command sequence according to a project plan as embodied in aseries of pre-programmed project menus. Examples of the project menusare shown in Tables 1, 3 and 5.

The system controller computer 280 transmits to the seismic sourcesystem 110 a “fire” (i.e. initiate a seismic signal) or other command ata time determined by the master clock 285 and according to applicationof the pre-loaded project menus to translate the desired downwardcommunication. Master clock 285 is preferably a highly accurate clockwith stability of 1 part per billion or better. The system controllercomputer 280 uses the master clock 285 to set the times of its commandsto the source control system such that the seismic shots are initiatedat precise and accurate times as called for in the project menus and asexpected by the downhole elements of the system. Power supply 290provides power to the system.

Upon receiving a command from system controller 120, the source controlcomputer 230 of the seismic source system 110 quickly checks the commandsignal for quality assurance by methods known to those of ordinary skillin the art. The source control processor 230 then triggers the seismicsignal generator 250 to initiate a seismic signal 160 beginning at therequired instant.

The system controller computer 280 also monitors the actual performanceof the seismic source 110 by processing and analyzing the seismicsignals detected by seismic monitor sensor array 115. For example, toestablish the quality of the transmitted seismic signals 160 the systemcontroller computer 280 may cross-correlate and compare a detectedseismic signal corresponding to the repeatable seismic signals 160 to astored rendition of the ideal seismic signal 160. Thus the systemcontroller computer 280 is able to perform quality assurance of theseismic source system. The system controller computer 280 may alsoprocess and analyze other recorded seismic data from the seismic sensorssystem 115. This seismic data may be generated by, for example, therotation of the drill bit assembly 195, by activation of geologic faultsor by movement of reservoir fluids. In the case of auxiliary signalingto the VSP receiver by means of bit rotation or pumping in apre-determined sequence, the seismic and other sensor data may beanalyzed for correct signaling characteristics.

Referring to FIG. 3, the VSP receiver 150 includes a seismic sensorsystem 330, one or more optional locking arms 336, 339, a signalprocessor 340, a power supply 345, and a process controller 350. Anoptional controllable while-drilling non-VSP logging tool 185 and anoptional telemetry transmitter 140 are coupled to the VSP receiver 150.

Each device and component shown in FIG. 3 is constructed to withstandthe pressure, temperature, vibration and other extreme physicalconditions present in downhole while-drilling applications. Appropriatedownhole housings, manufacturing techniques, and other adaptationsnecessary for a device to withstand downhole while-drilling conditions,and continue to be operable, are known in the art.

FIGS. 4-8 show the elements of FIG. 3 in greater detail. The seismicsensor system 330 of FIG. 4 includes one or more seismic sensors(preferably 3-component geophones and/or hydrophones) 410 connected topre-amp 440. Pre-amp 440 also connects to various other sensors 415which preferably include a borehole pressure sensor 417 and a boreholetemperature sensor 418. Optional locking arms 336 and 339 are shownengaged against borehole wall 405. A locking arm actuator system 420(also optional), pre-amplifier 440 and analog-to-digital converter 450,are provided power via power cable 470. These three elements arecontrolled via communication link 490. Data link 460 connects directlyto A/D converter 450 and carries digital signals from the A/D converterto the signal processor 340.

Locking arm 336 and locking arm actuator 420 are not required but may bedesirable to provide an improved physical coupling of the seismicreceiver system to the surrounding rock and thus to provide an improvedsensing of the seismic waves passing through the rock. However amalfunction of such a device could cause costly delays in the drillingoperation and hence they have been omitted from prior-art designs ofwhile-drilling VSP tools. A single locking arm 336 or multiple lockingarms may be provided if an improved design can provide a highly reliableconfiguration.

Geophone array 410 and hydrophone array 415 are suitable for detectingseismic waves. Downhole geophone and hydrophone designs are available inthe industry for VSP applications and these sensors may serve thepurposes of this invention. Preferably the geophone array 410 willinclude 3-component geophones capable of sensing motion in horizontal aswell as vertical directions. Hydrophones (which sense variations insurrounding fluid pressure) are not dependent on non-verticality of thelocal borehole (as geophones may be) and only require contact with theborehole fluids. Thus they may be relied upon to sense the seismicwavefield in nearly all expected conditions and are not limited byborehole orientation. A multiplicity of these geophone and hydrophonesensors may be necessary to overcome noise and provide clear receptionof the signal from the seismic source system 110.

By including a three-component geophone, advantage may be taken ofsource-generated seismic waves with particle motion in any spatialorientation. This gives advantage over a single component geophone,which in many situations would not provide adequate response totransverse particle motion. By choosing a three-component geophone bothpressure waves and shear waves emanating from the seismic source 110 maybe detected, giving an improved probability of accurate communication orsynchronization from the surface 105 to deep in the wellbore 180.

Pre-amp 440 filters and strengthens the signals from the geophone array410, hydrophone array 415 and other sensors 417 and 418.Analog-to-digital converter 450 transforms the analog signals that aregenerated by the sensors into digital signals suitable for manipulationby signal processors and micro controllers.

Alternatively the geophone and hydrophone arrays, pre-amp andanalog-to-digital converters may be replaced by MEMS devices thatperform the same overall functions but require less physical space.

Communication link 490 connects the seismic sensor system 330 to thesignal processor 340 and is used for transmission of commands and systeminformation to and from the signal processor 340. Seismic data is passedto the signal processor 340 via the data link 460. Electrical power isprovided to the seismic receiver from power supply 345 via power cable470.

Referring now to FIG. 5, a signal processor 340 is shown. Signalprocessor 340 connects to seismic sensor system 330 through data link460, power cable 470, and communication link 490, and includes allnecessary data storage and computing elements to provide for processingand analysis of the received seismic signals as well as essentialproject control information. Signal processor 340 therefore includescentral processing unit (CPU) 520 (such as a microprocessor,microcomputer, or the like), an accurate (such as a 10⁻⁷ accuracy orbetter) digital clock 510, a digital signal processor (DSP) 540, adynamic-random access memory unit (DRAM) 530, and a fixed head diskmemory unit or hard disk drive (HDD) 550. The downhole clock 510provides timing signals to the process controller 350 and via theprocess controller to other associated controllable devices. The signalprocessor 340 may be alternatively configured without the HDD 550 ifsufficient DRAM 530 or other memory can be provided to meet thecomputational and storage requirements. Also the functions of the CPU520 and DSP 540 can be combined if there is sufficient capabilityavailable to serve the computational requirements on one device.

The CPU 520 performs a variety of functions. For example, thecommencement (or cessation) of monitoring of drilling and pumping noiseis controlled by the CPU 520 via communication link 490. The activationand commencement happens when a set of pre-programmed conditions havebeen met. One such condition, the borehole fluid pressure, as detectedby the CPU 520's inspection of the output of borehole pressure sensor417, will have exceeded a pre-programmed pressure indicative of a tooldepth greater than the depth at which such a pressure level would exist.Likewise the borehole fluid temperature will have exceeded apre-programmed temperature indicative that a sufficient depth has beenreached to begin seismic shots. The signal output by the hydrophonearray 415 is inspected frequently by the CPU after the above twoconditions have been met so that it can assess the level of ambientseismic noise in the borehole fluid. The frequency of inspection issuitably about once every 3 seconds. Noise levels above a pre-programmedor dynamically chosen threshold level are indicative that activerotation of the drill bit assembly 195 is presently occurring. Thethreshold levels may be frequency dependent. If dynamically chosen, theyare selected by the CPU 520 based on intelligence related to expectednoise behavior during different drilling and drilling-related relatedactivities normally encountered in an operation of the current type andin the current environment. The CPU is programmed to know that seismicshots will never occur during active drilling or pumping. A somewhatlower threshold level is set so that ambient noise caused by fluid flowduring pumping operation will also mean that seismic shots will notpresently be initiated. When the periodic inspection of ambient noiseindicates that both drill and pump operation has ceased, the CPU 520activates the seismic recording process. If locking arms are availablethey may be programmed to be activated immediately prior to the start ofrecording. Both the geophone and hydrophone array output signals areamplified, filtered and digitized and stored in the memory (DRAM 530).

Another parameter that may be used along with pressure, temperature andambient noise levels is a minimum time prior to deployment, asdetermined by the downhole clock 510.

When monitored parameters indicative of depth subsequently show that thetool has departed the depth window for seismic recording, the seismicnoise monitoring activities can be discontinued, as per programmedinstructions of CPU 520.

Referring now to FIG. 6, power supply 345 connects through power cable470 and communication link 490 to the signal processor of FIG. 5.Included in power supply 345 are a battery pack 630, a power conditioner620, and power control 610.

The power supply 345 must provide electrical power via power cable 470to the seismic sensor system 330, the signal processor 340 and theprocess controller 350. Battery packs 630 and power conditioner 620under the control of the power control system 610 provide the requiredpower in the manner required by the served devices. Power conditioner620 ensures that the electricity from the battery pack 630 has thedesired parameters such as AC/DC, cycle, voltage, amperage, etc. Powercontrol 610 switches the power supply to a “sleep” or low-power modewhen and if desired.

Turning to FIG. 7, the process controller 350 connects to the powersupply 345 via communication link 490 and power cable 470. CPU 710connects via communications link 490 with signal processor 340 and otheractive elements of the downhole system. CPU 710 also connects to DRAM720, power cable 470 and command link 730. Command link 730 allowscommands to be sent from the process controller 350 to the telemetrytransmitter 140 and the controllable tool 185.

Referring now to FIG. 8, an exemplary controllable tool 185 is shown.The controllable tool 185 contains a central processing unit (CPU) 810,its own power supply 830, and an actuatable device 840. The actuatabledevice 840 responds to commands signaled by the CPU 810 via deviceactuator link 820. The controllable device may respond in any way thedevice is capable of performing. If it is an acoustic while-drillinglogging tool, for example, it may be commanded to perform or todiscontinue logging operation, to process its logs according topre-programmed or newly conveyed (via previous seismic communication)instructions and to provide resultant data to the process controller 350for further conveyance via the telemetry transmitter 140 to the wellmaster system controller 125.

In view of the large variety of possible controllable devices, numerouschanges are of course possible to the design of the controllable tool185. For instance, the power supplies 340 and 830 may be combined in thedesign of the system if desired. CPU 810 may be eliminated if itsfunctions are performed by another CPU or component in the system.Controllable tool 185 may also be modified for specific adaptation tothe system disclosed herein, such as by altering connection terminals,the quality or number of communication links, etc. However, oneadvantage to the teachings herein is its ability to utilize controllabledevices present in the prior art without extensive modification.

The telemetry transmitter 140 accepts commands from the processcontroller 350 which decides which data are to be transmitted and whenit will be transmitted. The telemetry transmitter may be a mud pulsesignal generator or any other suitable downhole-to-surface transmitter.

Enclosure of temperature-sensitive devices, especially including thedownhole clock 510, within a vacuum or other heat-insulated container isa feature of the preferred embodiment for applications in extremetemperature conditions such as encountered in deep boreholes. It shouldbe understood that the invention is not limited to the exact structuredisclosed in FIGS. 4-8. Electrical and mechanical elements and sensorsmay be added to the system as desired, and many of the components of thepreferred embodiment may be integrated with other components oreliminated if they are not required for a certain type of application.The computing (and data storage) functions of the signal processor 340,the process controller 350 and the controllable tool 185 or anycombination thereof may be combined if so desired by providing onecomputer and programming it to perform all of the required functions.For example, CPU 710 and DRAM 720 may be one and the same as CPU 520 andDRAM 530. Conversely, redundant components may be provided to guardagainst system failure.

The components of the system are preferably utilized according to themethods next described and illustrated in FIGS. 9-11. These methodsshare certain features with those disclosed in U.S. Pat. No. 6,002,640and U.S. Pat. No. 6,584,406, both hereby incorporated by reference forall purposes.

FIG. 9 is a process flowchart depicting the major significant processsteps that are conducted prior to and during the initial active drillingphase of a petroleum drilling project that utilizes the methods andsystems of this invention for seismic communication from the surface tothe while-drilling tools including the VSP receiver 150.

At step 900, off-site and other preliminary acts are taken to preparefor the VSP-while-drilling project. This includes the design andselection of project plans and project menus, as well the loading ofmenus into the appropriate CPU's, and other preparatory acts. Step 900also includes selection of the configuration for the VSP receiver 150and the repeatable seismic source system 110. Proper configurationensures adequate signal-to-noise ratios for the received seismicsignals. Reasonable prior testing and experience will provide a guide inthis selection. The telemetry transmitter 140 and one or morecontrollable tools 185 are also selected and interfaced with the VSPreceiver 150.

The project plan determines the list of possible commands from thesurface to the VSP receiver 150 that are needed to control its ownoperation and also for it to relay to the other controllable devices fortheir control, as well as the specific sequence of seismic shots thatindicate each particular command. If non-seismic-shot signals such as bysurface manipulation of the drilling processes are to be utilized theyare also included in the plan, however in the example of FIG. 9 onlyseismic communication is employed. (FIG. 12 provides an example thatincludes the non-seismic communications.) A Gantt chart may be preparedto enable an estimate of project duration and other aspects of theoperation that will help determine battery power requirements of thedownhole elements.

As part of the project plan development, project menus will also bedesigned. Examples of such menus are shown as TABLES 1, 3, and 5 of thisdocument. These project menus are designed to be appropriate for theproject requirements and devices to be controlled. The menu is invokedby generating a series of nearly identical seismic shots (“SISS”) fromthe site 100 according to the timing protocol contained in the menu orby signaling via manipulation of surface-controllable drilling processesor by a combination of these two categories of communication methods.

At step 910, the surface and downhole elements are positioned near thewell-head ready for commencement of active drilling operations. Theproject menus are loaded into the VSP system controller 120 and into theVSP receiver 150. All of the various programmable components of theuphole and downhole equipage are loaded with the appropriate programsand parameters chosen for the current project.

Just prior to commencement of drilling and while still at the surface,at step 920, the downhole clock 510 is synchronized with the masterclock 285. Step 930 is the commencement of fluid circulation and rotarymotion of the drill bit, i.e. active drilling begins.

While drilling continues the operator with the aid of controllingsoftware decides what the content of the next communication to the VSPreceiver 150 should be. The content may be in to form of commands orother information to be transmitted by signaling from the surface to theVSP receiver. This signal content is translated to times of shots,shot/no-shot binary signaling (including the number-of-shots form ofbinary signaling) and optionally into sequential manipulation of thedrilling processes; all of this is done according to the communicationprotocols and codes contained in the project menu. All of the activitydescribed in this paragraph is included in step 932.

At step 934 the operator pauses the drilling processes includingrotation and pumping activities, either specifically to enablecommunication of for any other purpose such as adding a section of drillpipe to the string.

At step 940, when the pressure and temperature sensors have detectedattainment of suitable pressure and temperature levels indicative ofreaching at least to the programmed minimum depth in the borehole, andthe seismic sensor system indicates sufficiently low ambient noiselevels indicative of temporary cessation of rotary motion and fluidpumping, the seismic signal transmission/listening phase begins. Duringthis phase, the downhole seismic sensor system 330 is placed into a“listen” mode by the CPU 520 to detect seismic signals. The “listen”mode entails activating the seismic sensor system 330 and recordingseismic data into memory. The listen mode may either be a continuousperiod of listening or a series of listening periods separated by shortpauses, based on the project plan and equipment capabilities. Alsoduring step 940, the seismic source 110 is placed into a “signalgeneration” mode during which it is capable of transmitting on shortnotice a series of nearly identical seismic signals (“SISS”) tocommunicate with components deep in the borehole and to provide seismicdata for the VSP method. This SISS also includes periods during which noseismic shot is initiated as explained in more detail below. Inaddition, the SISS may be utilized to estimate the drift of the downholeclock 510, to enable re-synchronization of the downhole clock to themaster clock 285, by determination of the amount of error that has builtup after Step 920.

At step 950, the signal processor 340 processes and analyzes a sequenceof recorded data for the current borehole location for the purpose ofidentifying valid shots and enhancing the signal-to-noise ratio of theseismic data. A best representation of the seismic signal (withmaximized signal-to-noise-ratio) for the current location in theborehole is formed by combining identified shots additively or in adifferent preferred way. Quality indices are computed to rate thesuccess of signal generation, reception and processing in terms ofnormalized cross-correlation peak amplitudes and times and conformanceto other project menu requirements.

At step 960 this best representation of the seismic signal is processedand analyzed downhole to determine the seismic travel time of the firstenergy from the seismic shots, as is of paramount interest in the VSPmethod (knowing the shot initiation times from the project menu and thearrival times from the downhole clock). The seismic shot information isprocessed by the signal processor 340 with benefit of the bestrepresentation of the seismic signal to determine the times ofinitiation of each shot in the current SISS. The shot initiation timesare constrained to a set of possible values according to the projectmenu. The seismic travel times are not known exactly beforehand and areone of the key items sought in the VSP method (being indicative ofgeologic and formation fluid parameters). Thus the VSP receiver, havingdetermined the shot initiation times and the arrival times of the firstenergy from the shots, can readily compute the values for the seismictravel times. These individual computed times should each be in erroronly by the amount of uncorrected downhole clock drift and any error inthe time determinations due to the influence of seismic noise.

At step 970 the shot initiation times determined in step 960 are thendecoded by the process controller 350 using the project menu andconverted to the language of the original message that was writtenuphole (in the form of commands and other information), and thentransmitted to the appropriate linked device or retained for its ownimplementation.

If a command has been received for action by the process controller 350,during step 980 it executes the command itself. Other controllabledevices (tools) receiving commands also take action accordingly in step980. For example a controllable logging tool 185 may be commanded toactivate using communicated parameters for a specified period of timeand it responds accordingly.

In step 982, when the command specifies that data from controllablelogging tool 185 is to be transmitted uphole, the command is thenconveyed, together with the specified data, to the process controller,from the process controller 350 to the telemetry transmitter 140, whichat the first opportunity transmits the data uphole. The processcontroller will similarly send its own acquired data, if so commanded,to the transmitter for its action.

At step 990 other processing may be conducted by the VSP receiver 150 toprepare the seismic images or related results from the survey fordelivery to the VSP system controller 120. This delivery may occur afterthe receiver is returned to the surface.

The system then returns to step 930 and drilling re-commences or (step995) the drilling string withdrawal from the borehole commences. Thewithdrawal may be necessitated by need for replacement of the drill bitassembly 195 if the drilling of the borehole has not been completed.

FIG. 10 continues after FIG. 9 and shows the steps that may be followedafter the commencement of withdrawal of the drilling string assembly 190from the borehole 180. In any case where re-occupation of a position inthe borehole allows a second stage of acquisition of recordings of aseries of seismic shots for that location, there exists the opportunityfor computation of the drift of the downhole clock 510 that occurredbetween the two periods of data acquisition. In the case of no clockdrift, the recorded data (in a noise free condition) would appearidentical for the two stages or periods. In the case of drift of, e.g. 3milliseconds during the intervening time, ideally the recorded datawould appear identical except for a shift of 3 milliseconds. If the VSPreceiver 150 knows that the two sequences of recording are for identicalborehole positions, and has available the germane seismic data, it cancompute the clock drift without awaiting a return to the surface. It maybe necessary to seismically communicate the borehole positions for eachof the two recording episodes for the VSP receiver to be able to linkthe two data sets, unless it can make this determination from pressure,temperature, comparison of the seismic data from the two times ofshooting, or other data.

Referring to FIG. 10, at step 995, withdrawal of the drill stringcommences. At step 1032 the operator at the surface prepares the nextmessage to be communicated to the VSP receiver 150. The CPU 520continues to keep activated the downhole seismic sensor system 330. Thesustained absence of sensor signals indicative of active drilling alertsprocess controller 350 to the possibility that removal of the drillingstring from the borehole has commenced.

At step 1034 the drilling string assembly withdrawal from the boreholeis halted temporarily for purpose of pipe section removal at thewell-head or for any other purpose, for example to record seismic shotsfor VSP purposes at a geologic interface of interest.

During step 1040, when monitoring of the ambient noise level indicatesthat pipe motion and fluid flow have ceased, the CPU 520 is again placedin the “listen mode” as described in the preceding discussion of FIG. 9.Noise levels will be set lower during the withdrawal phase then in thedrilling phase in order to detect these pauses because their is noactual drilling occurring between-pauses. Fluid pumping, drill stringrotation or drill string vibration can be initiated and paused incoordination with drilling string withdrawal to ensure the CPU 520successfully detects the correct times for listening, i.e. recordingseismic shots. A series of shots (the SISS) is launched by the seismicsource 110.

At step 1050 the shot identification and signal enhancement activitiesof CPU 520 occur. Again, the seismic travel times are computed for theidentified shots (step 1060) and the shot initiation times andshot/no-shot signals (including number of sequential shot signals) aredecoded and translated into the received message (step 1070).

During step 1080 process controller 350 implements its received commandsand linked logging tools implement commands directed to them.

The CPU 520 computes the clock drift in step 1075, if it has been madeaware of the re-occupation of a prior surveyed position in the boreholeand has access to the seismic data or processed seismic data from theprior activity.

The notification making it aware may have been provided in thejust-conveyed message itself; alternatively the CPU 520 may be informedby the signal processor 340 that it has determined that a previouslysurveyed borehole position has been re-shot. Signal processor 340 couldreadily gain this knowledge by comparison of the received waveforms forthe two periods of data acquisition for this same VSP receiver position,having been guided to a narrow range of potential positions by boreholetemperature and pressure measurements.

Next, in step 1082, data from these calculations and any other datarequired uphole (and commanded to be sent) is transmitted by thetelemetry transmitter 140 at the first available opportunity.

The CPU 520 conducts other VSP processing as it has been instructed andprogrammed to do in step 1090. Withdrawal of the drilling stringassembly from the borehole is continued in step 1091 and either theabove cycle is repeated for the next higher borehole location, or thewithdrawal is completed (step 1092).

After its return to the surface, when the VSP receiver 150 is againconnected to the VSP system controller 120, and this controller receivesall of the clock information, including current time, the VSP systemcontroller is able to compute the total downhole clock 510 drift thattranspired during the subsurface episode just completed by simplecomparison to the master clock 285 current time. This is included instep 1093.

All of the recorded data and processing results are uploaded from theVSP receiver 150 to the VSP system controller 120 during step 1094. Thesystem controller is then able to commence processing of all clock data,all communication and all VSP data for any purpose includingverification of results computed downhole, further signal enhancement,application of more elaborate methods, etc. The system controller alsoexpeditiously computes the optimum revision of the seismic velocitymodel and clock drift curve for the prior downhole episode. If it cancomplete this task in time, the revised models are supplied to the VSPreceiver before it begins its next downhole trip. Otherwise keyinformation from these calculations may be transmitted to the receiverafter it leaves the surface (by using seismic communication).

FIG. 11 is a process flow chart showing the preferred method ofwhile-drilling VSP, during the stage of extending the drilling stringassembly downward through previously shot borehole and re-synchronizingthe downhole clock prior to resumption of actual drilling. The flowchartbegins where the flowchart of FIG. 10 ends, with the revision of clockdrift and seismic velocity models (step 1096) utilizing data acquiredduring the prior downhole episode. Next, in step 1110, the revisedmodels are downloaded from the VSP system controller 120 to the VSPreceiver 150. While still at the surface the downhole clock 510 isre-synchronized with the master clock 285 (step 920).

The downward extension of the drilling string assembly into thepreviously drilled and seismically-shot borehole commences in step 1120.At each location previously used for recording of seismic shots the VSPsource may be activated to acquire additional seismic data for thatborehole location. If the surface location of the seismic source 110 hasnot been changed (as might be deliberately done if a ‘walkaway’ VSPsurvey is being acquired) there is an opportunity to improve the qualityof the VSP data for that position (by acquiring additional data andcombining it with prior data for improvement of signal-to-noise ratio)and also to improve the estimation of the clock drift for both the priorand current shooting. In the simplest approach the prior data and clockdrift estimate can be assumed to be correct and the clock drift for thecurrent downhole run can be determined by direct comparison of the twoseismic travel times. Applying this approach the VSP receiver candetermine the clock drift that occurs during each stage and for theentire period of downward extension and when drilling begins at thebottom of the borehole there will be no accumulated drift error in thedownhole clock. This is extremely advantageous in terms of the accuracyof seismic travel time measurements that are made as the borehole isextended further. The more elaborate approach of computing probableclock drift and velocity model errors can alternatively be used and alsowill attain significantly greater accuracy in determination of seismictravel times and clock drift in both the prior and current downholeruns.

The steps in FIG. 11 that are identical to the corresponding steps inFIGS. 9 and 10 retain the step numbers assigned in those figures. Theserecurring steps are not further explained in the following elucidation.

When, in step 1134, the downward extension of the drilling string ispaused (for addition of another section of drill pipe or deliberatelyjust for purposes of collecting seismic or other data) seismic shootingand recording may commence.

After computation of seismic initiation times and seismic travel timesin step 960, the CPU 520 of the signal processor 340 compares thecurrent data and results to prior seismic travel times (step 1165) andcomputes clock drift for the current run (step 1175). Key results fromthese calculations may be transmitted uphole in the following step 1182.Other VSP processing continues in step 1190.

The above sequence of steps repeats as the downward extension of thedrilling string re-commences (step 1120). When the bottom of theborehole has been reached (step 1195), after the completion of,the cycleof steps from step 932 through step 1190 for that location, drill bitrotation and pumping operations begin (step 930). Then the processes ofFIG. 9 are again followed as new borehole is created. When withdrawal isresumed, FIG. 10 applies.

FIG. 12 is a process flowchart that shows an alternative to theseismic-only downward communication depicted in FIGS. 9, 10 and 11. Thehybrid communication method combines seismic and other kinds of signalsthat can be conveyed to the VSP receiver 150 by special control of thedrilling subsystems including the processes of on/off rotation of thedrilling string assembly, on/off control of the drilling pumps andraising/lowering the drilling string assembly (possibly impacting thebit on the hole-bottom) and also inducing a characteristic vibrationsequence into the drill string by an ancillary system. Alternatively,acoustic signaling in the borehole fluid column could be used if meansare available. These processes are each controlled by the surfaceoperator and each generates characteristic seismic (or acoustic)signal—normally considered to be noise to the VSP seismic dataacquisition process. The processes are controllable but in such a manneras to make communication of information via their manipulation acumbersome low band-width process. However they can be very useful inconveyance of simple messages in a high-noise environment and in thatsense are more robust than signaling via seismic shots. When combinedwith seismic shots, these drilling signals can aid in extending thesuccess of seismic signaling to higher-noise environments and reduce thenumber of seismic shots required to communicate a given message.Drilling signals can precede seismic signals, as called for by theproject menu shown in Table 5, and may be used to alert the CPU 520 thatseismic shots are to immediately follow at the programmed times. If noseismic-shot communication is available for whatever reason, simplecommands conveyed by drilling signals alone can still be used to controlthe while-drilling logging tools (e.g. 185) and telemetry transmitter140 coupled to the VSP-receiver 150.

In FIG. 12, the steps that are the same as in the prior FIG. 9 arenumbered identically. After the pause in drilling at step 934, signalgeneration via on/off rotation of the drilling string assembly 190,signal generation by on/off activation of the borehole fluid pumping,signal generation by raising/lowering the drilling string, vibration ofthe drill string and/or acoustic signaling takes place, according to theproject menu protocols. One, two or any number of these techniques maybe employed in a pre-determined fashion.

The VSP receiver 150 detects the variations in its sensors' outputs thatindicate the reception of the signals (mainly in terms of amplitudes andfrequency characteristics of seismic energy as a function of time). Thereceived drill signals are interpreted according to the project menu instep 1250. Any commands or other useful information that can be gleanedfrom the signals may be utilized at once. For example the message may bethat a seismic communication will immediately follow with shotsinitiating at some of the pre-programmed times. (This is as in theexample from TABLE 5).

In step 940 the SISS immediately commences after the drill signals.Steps 950 and 960 follow as in the example of FIG. 9. The shot/no-shotindicators and the computed seismic initiation times are conveyed to thehybrid message decoder which has already received the drilling processsignals.

In step 1270 all of this information is decoded and translated into thehybrid message that the surface operator intended to convey. Anycommands invoked by the message are implemented in step 1280. If theyinvolve other controllable tools the relevant commands and informationare further sent to those tools.

If called for by the message or the menu, data is then transmitteduphole in step 982. The sequence of processes then continues as in FIG.9 but with the added steps in this FIG. 12 for each iteration.

Although the processes shown in flowcharts of FIG. 10 and 11 have notbeen modified to add the hybrid communication processes, it can beappreciated that communication to the VSP receiver 150 using variationof the surface-controllable drilling operations (as in FIG. 12) can alsobe combined with the process steps shown in FIGS. 10 and 11. However,only those processes that do not require contact with the bottom of theborehole can be applied. Therefore in these applications the hybridmethod is limited to using variation of pumping, rotation of the drillstring without actually drilling, raising and lowering the drill string,inducing a characteristic vibration into the drill string at thesurface, and/or acoustic signaling.

As indicated above, a series of nearly identical seismic shots (“SISS”)and/or manipulation of surface-controllable drilling operations are usedto communicate from the surface to a downhole device. A particular SISSis initiated only at start-of-programmed-time-window time (defined inthe program menu) plus integral multiples of the parameter ZPTW(programmed time window interval), also contained in the menu. Withineach SISS, shots may be initiated only at integral multiples of the unittime step. The unit time step is an important feature that enables thedetermination of downhole clock drift and exact shot initiation time inthe presence of seismic noise. The unit time step is set at asufficiently large value that clock drift plus noise influence will notcause an incorrect identification of the shot initiation time by the VSPreceiver 150. Under good signal conditions a value of 20 millisecondsfor the unit time step would be appropriate. Under poor signalconditions a value of 50 milliseconds would be advisable.

The programmed time window interval (ZPTW) may be set to a sufficientlysmall value that one interval almost immediately follows the previousinterval in the while-drilling application of the signaling method.Furthermore, it may be set such that each time window immediatelyfollows the prior window by the interval of time between the shots. Inthis way, the practitioner may schedule potential seismic shots at timesseparated by a constant time interval, from beginning to end of thedownhole mission, if he does not desire to use the time-delay method ofsignaling (the time delay method is employed in the project menu ofTABLE 3). Using a sufficiently small programmed time window intervalguarantees there will be no significant delay required beforecommencement of shooting as any opportunity to acquire data becomesavailable. The project menu can be specified such that the first seismicshot of any sequence of shots defines the beginning time of theprogrammed time window. This approach makes best use of available timeand reduces project costs accordingly. It also makes identification ofshots a simpler mathematical process because of the periodicity of shotsin any actual shooting sequence.

When it is desired to use the time-shift method of signaling it is bestfor shot-identification purposes to begin a sequence of shooting with aseries of shoots equally spaced in time followed by the shots which maybe time shifted to communicate information. This method is exemplifiedin the project menu shown in TABLE 3.

It can also be appreciated that each transmitted communication/commandshot may be used to correct for clock drift as generally explainedherein and in U.S. Pat. No. 6,002,640. Further to this, by creating arecord of temperature history and a record of clock drift history, thetwo may be compared and used to aid in interpolation of clock driftbetween times of direct master clock re-synchronization and also betweentimes of seismically-based drift computation; this technique is alsouseful in extrapolating clock drift variations when only temperaturedata is known.

Referring to FIG. 13 a and 13 b, a technique of cross correlationincludes comparing two recorded seismic shots and deriving a degree offit between them. If a high degree of fit is present, both recordedseismic shots can be reliably considered to have been detected. The timeof arrival can also be reliably measured for each shot of the SISS. Inthis document the term cross-correlations refer to normalizedcross-correlations that are formed by computing the zero-lag amplitudesof the auto-correlations of the two time functions being compared anddividing the cross-correlation amplitudes by the square root of theproduct of these two zero-lag amplitudes. If the two input timefunctions are identical the peak value, i.e. zero-lag amplitude of thenormalized cross-correlation will have a value of unity. Noise presentin the two amplitude-versus-time functions being correlated will resultin a lower value of the peak amplitude and probably a time shift awayfrom the zero-lag position. The amplitude of the peak value and timeshift can be used as measures of the signal-to-noise ratio of the twoinput functions.

A threshold value of the amplitude or “correlation coefficient” can beset or established that, if exceeded by the peak amplitude of thenormalized cross-correlation, indicates that a communication/commandshot was received. The threshold value can be adaptively set based onobserved signal-to-noise ratios, or may be preset at the surface priorto deployment downhole. An example of a pre-set correlation coefficientthreshold is a value of 0.70. If this value is exceeded it is extremelylikely that a shot was in fact initiated.

FIGS. 13 a and 13 b illustrate the application of the cross-correlationmethod to determine presence or absence of a shot initiated at thepre-programmed time. Although the cross-correlation method is depictedhere, numerous processing techniques are known in the field of signalprocessing to determine whether a signal has been received and each ofthese is available to one of ordinary skill for this invention. In FIG.13A, there is shown first an enhanced seismic shot signal estimate; thisestimate may be formed from any number of shots recorded for the currentVSP receiver 150 borehole location by mathematical combination of theavailable data to provide an optimized representation of the seismicsignal. This signal estimate amplitude series is cross-correlated withdata recorded in four sequential time windows in which there may havebeen seismic shots initiated according to the relevant project menu. Inthe example shown three of the four cross-correlations have positivepeak amplitudes which exceed the threshold value which was set for theidentification of a shot (0.70). (The correlation amplitudes have beennormalized as described above such that the cross-correlation ofidentical input amplitude series would exhibit a peak coefficient valueof unity.) The fourth correlation does not have any amplitude whichexceeds the threshold and therefore it is deemed that no shot occurred.In practice a correlation coefficient threshold of 0.70 would ensure ahigh likelihood that “no-shot” instances would not be improperlyidentified as shots. In this manner correlation coefficients can be usedfor each potential shot being evaluated for presence/absence of anactual shot and used to appraise the quality of the results. Othersimilar quality criteria thresholds such as the scatter of peakamplitude times can be established to aid in the decision makingregarding actions to take as a result of the seismic communication.

In FIG. 13 a, SHOT 3 as recorded contains noise following the signalwhich is much higher than on SHOTS 1 and 2. The amplitude series labeledSHOT 4 was at the time of a potential shot, according to the projectmenu, but in fact no shot occurred. Thus this recording contains onlyambient noise.

In FIG. 13 b the cross-correlations of SHOTS 1 and 2 yield nearlysymmetrical functions (with peaks very near to time zero) with high peakcorrelation values of 0.91 and 0.85, indicating excellentsignal-to-noise ratios in the recorded data. The cross-correlation fornoisy SHOT 3 has a peak correlation value of 0.71 (barely acceptable)and it is displaced by 7 milliseconds. However this does meet thecriterion set for identification of a shot (>0.70). The recording forpotential SHOT 4 when cross-correlated does not exhibit symmetry abouttime zero and yields a peak cross-correlation of 0.45, well below therequired level of 0.70. Therefore it is concluded that no shot occurred.This sequence of three identified shots and one confirmed no-shot couldbe translated to a binary sequence 1110 according to one method of thepreferred embodiment (for example, as implemented by the project menu inTABLE 1).

The time shifts measured for the valid shots in this example (−2, +1 and−7) or the cross-correlation functions themselves can be combined toprovide an estimate of the drift of downhole clock 510 between the timerepresentative of the recording of the reference function (the enhancedseismic shot/signal estimate as labeled in FIG. 13 a) and the time ofrecording of these shots. Simple numerical averaging of the three timeshifts gives a value of −2.67 milliseconds. A weighted average thataccounts for the poorer quality of the SHOT 3 data yields a value of−1.5 milliseconds. Other methods such as combining cross-correlationsadditively or combining recorded data before correlation with thereference function may yield an even more accurate estimate of the driftand thus reduce the influence of noise. Thus the example data in FIGS.13 a and 13 b can serve the purposes of communication as well as ofre-synchronization of the downhole clock. And of course the same seismicdata as in FIG. 13 a can be processed for VSP purposes.

The method of FIGS. 13 a and 13 b assume a near-exact repetition fromthe same site 100 of the seismic source wavelet 160. If this can beachieved, variation in the resultant cross-correlations from acorrelation coefficient of unity may then be ascribed to noise (ambientplus system noise). Thus, significant unintended variation in theseismic source wavelet or significant movement of the seismic sourcesmay compromise the integrity of the communication.

Where SISS shots are used to communicate commands or information to thedownhole components, the values corresponding to one or a series ofcommand/communication shots are translated into commands and informationaccording to a set of Menus programmed in the relevant CPU's (bothsurface and downhole), such as shown in TABLES 1-6. Each menu comprisesa table of potential shot time values and/or shot/no-shot selectionversus message information enabling the CPU to translate delays betweenseismic shots and the presence/absence of shots into usable information.For a particular CPU, a general menu is established which defines themost general case for the capabilities of that CPU or controllabledevice. Each general menu is composed of many variables, including aunique identifier. Standard defaults may be provided for certainvariables. If there is not a general default for a variable, it may bedetermined solely by the SISS, and thus the general menu can be useddirectly (as can any menu).

For a given project, a single project menu is defined which includes allof the parameters of the applicable general menu and adds all of theproject-specific parameters that apply. The project menu alsoestablishes any variable that will not vary throughout the project orproduction schedule by means of setting default values. The project menufurther defines project ranges and valid values for other variables.Some parameters are not explicitly stored in the menus, but rather arealgorithmically computed from the shot interval times and/or number ofshots in the SISS.

The SISS can be used to enable a more specific menu and thereby setadditional default values. The SISS can also be used to enable a moregeneral menu. In addition, the SISS can instruct a portion only of theprocess controller 140 to sleep or ignore subsequent commands, or tochange menus, for example.

Examples of project menus are shown in TABLES 1, 3 and 5. An example ofapplication of the project menu from TABLE 1 is shown in TABLE 2.Examples of the application of project menu of TABLES 3 and 5 are shownin TABLES 4 and 6.

Each menu includes parameters which are held constant for the particularproject and variable parameters. The variable parameters may includecontrol settings for any elements of the downhole system such as theseismic receiver, the power supply or for the actuatable device. Theactuation commands for the actuatable device are the second class ofvariable parameters and as such are of primary importance.

Looking in detail at TABLE 1, a project menu is shown according to thepreferred embodiment with provision for seismic communication from afixed surface site to a while drilling VSP tool, linked to othercontrollable tools. In this project menu only binary seismic signalingis used. The parameters that are constant for the duration of theproject are shown in the top half of the menu. The parameters that canbe varied and their controlling seismic shots are shown in the lowerhalf of the table. After the project name, the unit time step, UTS, isspecified to be 20 milliseconds. The Listen Time is 6 seconds meaningthat seismic data will be recorded for at least 6 seconds beginning ateach time of potential initiation of a shot. The Buffer Time is 4seconds. Together these two parameters add to 10 seconds which meansthat potential shots can be initiated at integer multiples of 10seconds. The Programmed Time Window (PTW) intervals are set toCONTINUOUS meaning they can begin at any integer multiple of 10 secondsif a first shot is initiated at that time and NOISE has been less thenthe specified 10 microbars for at least 10 seconds. Other parameters arealso assigned values in this section of the project menu and remainfixed for the duration of the project.

In the lower portion of TABLE 1, the project Variable CommunicatedParameters are set forth. In this part of the project menu the seismicshots are shown in sequential order. The first ten shots (N1 throughN10) will occur with 10 second intervals between shots, i.e. at integermultiples of 10 seconds. No parameters are conveyed by these shots.Following the tenth shot, there may be from one to nine additional shots(M1 through M9). Each of these is a potential shot which if actuallyinitiated signifies a binary value of ‘1’ and if not initiated signifiesa binary value of ‘0’. Shot M1 is used to control the transmission ofthe seismic travel time for the current receiver position uphole. Avalue of ‘1’ means to transmit the seismic travel time value. Shot M2controls the transmission of a quality index. Shot M3 controls thetransmission of the calculated downhole clock drift for the currentshooting sequence. Shot M4 dictates the transmission or not of thecurrent estimate of the velocity model error for the current receiverposition. Shot M5, if initiated, calls for transmission of the currentbattery status. Shot M6 is used to activate or deactivate a linked tool,in this case a sonic while-drilling tool. Shot M7 controls thetransmission of data from this tool. Similar usages are prescribed inthe project menu for shots M8 and M9 for another linked while-drillingtool.

The complete shooting and recording sequence for this project menuconsumes up to 190 seconds. This is less than the time normally consumedduring the addition or removal of a drill pipe section as the drillingstring is lengthened or shortened. The guaranteed minimum number ofseismic shots, ten, ensures ample redundancy to facilitate the formationof a sufficiently good signal model by summation of data or moreelaborate methods. Data may be summed before any shots is identifiedwith a good likelihood that all or most of the ten shots will beincluded in the summation. Because there are no deliberate time shiftsamong the shots in this menu the signal will be summed exactly in phase.When a good signal model has been formed in this way, cross-correlationscan be formed as an aid in detection of the potential shots M1 throughM9. When detected., these shots can be combined with prior detectedshots to build an improved model, and the process can be iterated forfurther incremental improvement in the model as more shots areidentified. This would be especially useful in the case that thebeginning of the shooting sequence had been assumed wrongly in the firstpass.

An alternative approach to shot identification is to first use a finalsignal model for a nearby VSP receiver position and apply it to theseismic data from the current position. If the adjacent position issufficiently close to the current position it's seismic signal will havea high degree of similarity to the signal for the current position,albeit time shifted by a small amount. After shots are identified forthe current position they can be combined to provide the best model forthe current position. Normally if the receiver positions are within 400feet, e.g., this approach could make shot identification easier and morereliable in where noise conditions are challenging. Signal models fromadjacent positions can also be compared by cross-correlation todetermine the amount of seismic travel time difference between them, asa means of confirmation of travel time measurements made directly foreach position.

In TABLE 2, an example of the implementation of the project menu ofTABLE 1 is shown. The operator at the surface decides to send themessage that calls for all of the possible actions except for the lasttwo (he does not wish to activate WD Tool 3 and doesn't want to send anyWD Tool 3 data uphole). Therefore he activates the seismic controllercomputer 280 and asks it to send at the first quiet interval (whendrilling or lifting of the drilling string assembly 190 ceases for atleast 10 seconds) the SISS that conveys this message. The appropriateSISS will have shots N1 through N10 followed by shots M1 through M7.Potential shots M8 and M9 will not occur.

The VSP receiver 150 records the seismic data during the correct timewindow as quiet conditions have pertained for at least 10 seconds. Itsums or otherwise combines data from the recorded times when potentialshots could have been initiated and their data received to form a signalmodel. This is cross-correlated with the individual contributingpotential shot windows to identify actual shots. This process continuesthrough a series of iterations that improves the identification of theshots and increases the quality of cross-correlations that arecalculated. A column entitled ‘Observed Corr. Coeff.’ lists the bestresults. If the value is greater than the programmed value of 0.7 a shotis deemed to have been identified. In this example all of the shots havebeen correctly identified and a binary ‘1’ or ‘0’ assigned accordingly.Elimination of the contribution from the potential shots that were notactually fired results in an Average Corr. Coeff. of 0.84, an indicatorof the quality of the results. ‘Observed Raw Times’ are listed for theidentified shots—these are the times of the cross-correlation peakamplitude values added to the appropriate ‘Corresponding Shot Times’ inthe menu. These values represent the computed shot initiation times forthe shots. The ‘Delta-to-Model Times’ are the values by which thecorrelation peak times differ from the shot initiation times. Ideallythey are all zero. The presence of seismic noise and downhole clockdrift cause them to be non-zero. They can be averaged or otherwisecombined to give a best-estimate of the downhole clock drift, which inthe example shown is 1.0 milliseconds fast. Delta-to-model times canthen be recalculated taking out clock drift to give times that arenon-zero only due to the effect of noise. In this example the standarddeviation of these residual time errors is 1.2 milliseconds. Thisquantity is used as a quality index for the overall process and isindicative of how much reliance should be placed on the seismic traveltimes that have been determined, as well as on the clock drift.

TABLE 3 contains a project menu that like TABLE 1 utilizes binaryseismic shots following a series of shots but, unlike the prior example,also has a final sequence of shots that utilizes time-shift signaling.Shots N1 through N10 are always initiated first in the sequence,followed by shots M1 through M4 that use the binary protocol as in theprior example to control telemetry of data from the downhole transmitterto the surface. Following these shots, time-shift signaling is used forshots M5 through M9. Shot M5 may be initiated at any time from 140 to144 seconds in steps of 20 milliseconds. The particular time chosencommunicates the current VSP receiver 150 position in the borehole interms of number of drill pipe section lengths. The current seismicsource offset in the horizontal direction from the VSP tool iscommunicated by shot M6. This shot will range from 154 to 154.5 secondsinitiation time, again in integral multiples of the unit time step of 20milliseconds. The shot M7 conveys the latest uphole estimate of thedownhole clock drift (made with benefit of telemetered seismic traveltimes and other information available uphole). Shot M8 indicates thenumber of shots in this shooting sequence and shot M9 indicates thenumber of shots in the next planned sequence. These values will be ofbenefit in the process of shot identification downhole. Numericalparameters with a range of potential values are thus communicated usingthe time shift method of seismic communication while parameters having asimple binary expression are conveniently communicated by using thebinary method. The binary method in one of its adaptations can be usedas a means of signaling by using a variable number of sequential shots,of course.

TABLE 4 provides an illustration of the utilization via an exemplarySISS of the project menu of TABLE 3. In this example all nineteen shotsare duly identified, quality control criteria are exceeded and themessage is correctly received and interpreted. The binary shots havebeen used to command certain downhole actions. The time-shifted seismicshots have been used to communicate that the VSP receiver 150 is 12,200feet from the surface along the borehole trajectory, the repeatableseismic source 110 is offset 1300 feet from the receiver, the downholeclock was estimated to be 1.00 milliseconds fast, there are nineteenshots in the current SISS and there are nineteen shots planned for thenext SISS.

TABLE 5 provides an example of a project menu used to communicate fromthe surface to the VSP receiver 150 by utilizing binary seismic shotscombined with activation and pausing of drill rotation as a hybridcommunication method. The activation and pausing of drill rotationbegins with a pause of duration 30 seconds. This is followed by 30seconds of drilling, then 30 seconds of pause and then another 30seconds of drilling. Correct adherence to start and stop times need onlybe within 5 seconds according to the project menu (to allow for varianceinduced by the operator or the processes themselves). After the secondpause of 30 seconds quiet conditions are maintained for another 180seconds to allow successful seismic communication via the SISS. In thisproject menu the drill rotation signals has been used as a means ofconfirming that an SISS is to follow immediately. The seismiccommunication portion of this project menu is the same as that in themenu of TABLE 1. It utilizes binary seismic shots and no time-shiftseismic shots.

TABLE 6 is an example of the utilization of the hybrid project menu ofTABLE 5 in a specific case. The VSP receiver 150 correctly perceives thedrill rotation and pause alternation and then prepares to receive theseismic communication according to the remainder of the menu. Recordingis not initiated until the drill conveyed message has been received andinterpreted, conserving power and computer resources. The VSP receivercorrectly receives, records, processes and interprets the hybrid messagein this example.

Downhole clock 510 drift is determined for the period between an initialseismic measurement and a subsequent seismic measurement at theidentical receiver position as has been revealed in the precedingdescriptions and illustrations. Assuming the correctness of each suchdetermination of drift and ignoring for the present discussion theeffect of noise in possibly injecting error into the driftdeterminations, there is a limitation in the proposed method due to thefact that drift is not calculated directly for consecutive positions inthe borehole but only between successive occupations of the sameposition. This necessitates construction of a drift rate graph thatprovides a best determination of the probable drift rate (and means ofcalculating drift) between each pair of consecutively occupied positionsin the borehole for the entire duration of the project.

Beginning at the first position that is re-occupied and re-shot, forexample the deepest position attained, as at the end of FIG. 9 andbeginning of FIG. 10, a determination of total drift and drift rate ismade for the period between the two acquisitions of seismic data. Thereis no issue with assuming that drift rate was constant during thisperiod as no intervening seismic measurements were made. Next, the drillstring is pulled to the next higher surveyed position in the boreholeand it is re-shot. The total drift and drift rate are determined for thetime period between the two acquisitions of seismic data. This is for alonger period and contains the shorter period that was surveyed justprior. There is no direct way of knowing from the seismic data or thepair of drift calculations whether the drift rate at the beginning ofthe period and the drift rate at the end of the period were identical.Thus the practitioner must either make some assumption such as that thedrift rates were identical or must exercise a rationale that provides adifferent attribution of drift rates and the drift increments betweenthe beginning period and the ending period.

If the drift rate is calculated to be the same as for the internalindependently-measured period, of course, the most reasonable assumptionis that drift rate held constant throughout the entire interval.However, if the initial calculation of the overall drift rate for theoverall period differs from that calculated for the contained period, adifferent drift rate must be ascribed to the beginning and endingperiods (different from that of the contained period). These twointervals may be assumed to have identical drift rates or the two ratesmay be assumed to differ, so long as the total drift for the overallperiod is honored. If no guidance is available the beginning and endingperiods are assumed to have had the same drift rate. If otherinformation is available, such as temperature history of the downholeclock 510, a different assumption may be applied, such as that the driftrate was proportional to temperature of the clock.

As the process continues and more borehole positions are shot, similarcalculations to those described in the preceding paragraph are made.Drift and drift rate graphs for the downhole clock 510 are built for thefirst measured time period and extended until the entire time period isgraphed, from the initial synchronization to the master clock 285 untilreturn of the downhole clock to the surface and its finalre-synchronization to the master clock. Thus after completion of thedownhole episode a completed graph of drift and drift rate is availableto the computer processors and the human overseers.

Following the downhole episode described in the preceding paragraphsanother may follow. If positions in the borehole that were previouslyshot and graphed are re-shot, further drift rate information is gainedas well as additional independent seismic travel time measurements. Thenew information may be processed independently and it may also becombined with the information and results from the prior episode. Theclock drift rate and drift graphs from the prior episode may be revisedas a result of incorporation of the new independent measurements.Reliance on drift rate assumptions made during the first episode may bereduced and the accuracy of the drift rate and drift graph for thatepisode improved. Conversely the calculations from the prior episode maybe used to improve the results from the current episode, improving thebasis of drift rate assumptions. Best drift and drift rate knowledge isavailable after all of the seismic information for the project has beenacquired and combined. However, the drift and drift rates calculatedduring earlier stages will have greatly enhanced the quality of theseismic travel time measurements and estimates made then. This early‘imperfect’ information will have been of great value in operationaldecisions that are necessarily made at early stages, while drillingoperations are underway.

In any determination of seismic travel time according to the preferredembodiment of the invention, such as illustrated by FIG. 13, theinfluence of seismic noise may be to introduce error into thedetermination. The scatter of cross-correlation peak times shown inTABLES 2, 4 and 6 is such as can be caused by seismic noise. Taking aseries of identical shots to convey one piece of information enablemethods of reducing noise influence on the quality of seismiccommunication, synchronization and VSP imaging. In poor signal-to-noiseratio situations, such as might occur at great depths in a borehole, itis beneficial to use a seismic travel time model for the current projectthat integrates information gleaned from a variety of sources to providethe geophysicist's expectation of travel times for each pair of sourceand receiver positions. These sources would normally include velocityand travel times maps and models from prior 3D seismic surveys, resultsfrom prior VSP surveys in adjacent wells, etc. And as the currentproject obtains seismic travel times, e.g. in VSP surveying of theshallower borehole, this information would also be incorporated into themodel. The seismic travel time model for the current borehole can beused to constrain arrival time measurements and reduce the likelihoodthat excessive noise might corrupt clock drift measurements.Measurements outside of an allowable range are simply withheld fromincorporation in the clock drift and drift rate graphs in this approach.Subsequent measurements might confirm the correctness of themeasurements resulting instead in a revision of the seismic travel timemodel. Thus this is a conservative approach that yields the mostreasonable results that can be achieved under the conditions of theproject.

While preferred embodiments of this invention have been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit or teaching of this invention. Theembodiments described herein are exemplary only and are not limiting.Many variations and modifications of the system and apparatus arepossible and are within the scope of the invention. Accordingly, thescope of protection is not limited to the embodiments described herein,but is only limited by the claims that follow, the scope of which shallinclude all equivalents of the subject matter of the claims.

1. A while-drilling method of vertical-seismic-profiling comprising thesteps of: (a) providing a drill string in a borehole for advancing theextent of said borehole. (b) providing a seismic source of substantiallyrepeatable seismic signals initiated by seismic shots having aninitiation time occurring exclusively within time windows selected fromamong a series of regularly recurring time windows for transmission ofinformation to a subterranean location; (c) providing on said drillstring, a subterranean signal receiver for receiving said seismicsignals emitted by said seismic shots and transmitting said signals to asubterranean processor, said processor being programmed to; i. verifythe authenticity of received seismic signals as originating from saidseismic source, ii. discern the presence or absence of verified signalswithin recurring time windows, iii. translate a first portion ofoperative information from the presence or absence of said verifiedsignals within a recurring time window; iv. determine the initiationtimes of said verified signals; and, v. translate a second portion ofoperative information from said initiation times of said verifiedsignals, and (d) said processor modifying its operation in accordancewith said operative information.
 2. The method of claim 1 in which saidprocessor determines that at least one portion of said operativeinformation is for an associated underground controllable tool andcommunicates said one portion of operative information to said tool. 3.The method of claim 2 in which said tool receives said one portion ofsaid operative information and actuates said tool in accordance withsaid operative information.
 4. The method of claim 2 in which saidassociated underground controllable tool is a logging tool.
 5. Themethod of claim 2 in which said associated underground controllable toolis an uphole communication device.
 6. The method of claim 5 in whichsaid uphole communication device is a mud pulse telemetry transmitter.7. The method of claim 1 in which said processor determines said firstportion of said operative information from the number of consecutivetime windows in which said shots were initiated.
 8. A method asdescribed by claim 1 wherein said subterranean processor determines afirst time differential between a predetermined moment relative to atime window opening and the receipt moment of a verified signal. 9 Amethod as described by claim 8 wherein said first time differentialrepresents a seismic signal travel time between said surface source andsaid subterranean receiver at the respective signal receiver position.10. A method as described by claim 9 wherein said first timedifferential is determined at a plurality of signal receiver positionsalong a length of said borehole. 11 A method as described by claim 1wherein the initiation times of said seismic shots are restricted totimes during which ambient seismic noise is below a threshold level. 12.A method as described by claim 1 wherein the initiation times of saidseismic shots are restricted to times during which said subterraneansignal receiver is within a predetermined depth range.
 13. The method ofclaim 12 wherein said subterranean processor monitors boreholetemperature to determine current depth and records seismic data onlyduring a predetermined depth range.
 14. The method of claim 12 whereinsaid subterranean processor monitors borehole pressure to determinecurrent depth and records seismic data only during a predetermined depthrange.
 15. A method as described by claim 1 wherein said seismic signalsource comprises a signal controller having a first clock and whereinsaid subterranean processor includes a second clock, said subterraneanprocessor determining a first time differential between a predeterminedmoment relative to a time window opening and the receipt moment of averified signal.
 16. A method as described by claim 15 wherein saidfirst time differential represents a seismic signal travel time betweensaid surface source and said subterranean receiver at the respectivesignal receiver position. 17 A method as described by claim 16 whereinsaid first time differential is determined at a plurality of signalreceiver positions along a length of said borehole.
 18. A method asdescribed by claim 17 wherein the first time differentials respective toa plurality of receiver positions along said borehole are processed tocompute geologic characteristics between said seismic signal source andsaid signal receiver.
 19. A method as described by claim 15 wherein saidsubterranean processor determines a second time differential between thefirst time differential of a subsequent shot compared to the first timedifferential of an earlier shot to synchronize said second clock withsaid first clock.
 20. A method as described by claim 19 wherein verifiedsignals respective to said earlier shot and said subsequent shot arereceived at substantially the same position within said borehole.
 21. Amethod as described by claim 20 wherein said verified signals from saidsubsequent shot serve to synchronize said second clock to said firstclock and simultaneously serve to compute geologic characteristicsbetween said seismic signal source and said signal receiver
 22. A methodas described in claim 21 wherein said verified signals from saidsubsequent shot also simultaneously serves to cause actuation of saidtool.
 23. The method as described in claim 1 wherein surfacemanipulation of drilling processes provides supplementary signals tosaid subterranean signal receiver and said subterranean processor which,taken together with said seismic signals from said seismic shots,provides a third portion of operative information to said processor,said processor modifying its operation in accordance with said first,said second, and said third portions of operative information.
 24. Themethod of claim 23 in which said processor determines that a portion ofsaid operative information is for an associated underground controllabletool and communicates said portion of said operative information to saidtool.
 25. The method of claim 24 in which said tool receives saidportion of said operative information and actuates in accordance withsaid operative information.
 26. The method of claim 24 in which saidassociated underground controllable tool is a logging tool.
 27. Themethod of claim 24 in which said associated underground controllabletool is an uphole communication device.
 28. The method of claim 27 inwhich said uphole communication device is a mud pulse telemetrytransmitter.
 29. The method of claim 23 in which said surfacemanipulation of drilling processes includes sequential pumpingvariations to cause sequential borehole pressure variations that conveysaid third portion of operative information.
 30. The method of claim 23in which said surface manipulation of drilling processes includessequential pumping variations to cause sequential borehole fluid flowvariations that convey said third portion of operative information. 31.The method of claim 23 in which said surface manipulation of drillingprocesses includes sequential drill bit motion to cause sequentialseismic energy variations that convey said third portion of operativeinformation.
 32. A while-drilling vertical-seismic-profiling (VSP)apparatus comprising: (a) a source of substantially repeatable seismicsignals positioned proximately of the Earth's surface; (b) a seismicsignal controller having a first clock for initiating signals from saidsource at selected moments, said selected moments occurring exclusivelywithin time windows selected from among a regularly recurring series oftime windows (c) a drill string element having a data processor, asecond clock and an operatively associated seismic signal receiversecured thereto; and, (d) a data processor control program for; i.analyzing successive seismic signals received within said selected timewindows by said signal receiver for amplitude-time correspondence andfor verifying a signal received by said receiver as being initiated bysaid source; ii. measuring a first time differential between apredetermined moment relative to an opening of the selected window andreceipt of a verified signal; and, iii. measuring a second timedifferential between successive first time differentials to determine aclock synchronization drift value.
 33. A while-drillingvertical-seismic-profiling apparatus as described by claim 32 wherein asignal controller program causes successive seismic signals from saidsource to be initiated at selected variable time intervals. 34 Awhile-drilling vertical-seismic-profiling apparatus as described byclaim 33 wherein said data processor control program measures saidvariable time intervals and determines encoded operational informationtherefrom.
 35. A while-drilling vertical-seismic-profiling apparatus asdescribed by claim 34 wherein said signal controller program preventssaid source from initiating seismic signals when a drill stringcomprising said element is operating to advance said borehole while saidregularly recurring time window series continues.
 36. A while-drillingvertical-seismic-profiling apparatus as described by claim 32 whereinsaid drill string element further comprises signal transmission meansfor transmitting information comprising said measurements to saidseismic signal controller. 37 An apparatus forvertical-seismic-profiling while drilling comprising: (a) a drill stringin a borehole for advancing the extent of said borehole. (b) acontrollable seismic source of capable of emitting substantiallyidentical seismic signals initiated by seismic shots having aninitiation time occurring exclusively within time windows selected fromamong a series of regularly recurring time windows for transmission ofinformation to a subterranean location; (c) affixed within said drillstring in proximity to a drill bit, a subterranean signal receiver andprocessor, said receiver constructed to be capable of receiving saidseismic signals emitted by said seismic source and of transmitting saidsignals to said processor, said processor being programmed to and befurther able to perform the tasks of: i. verification of theauthenticity of received seismic signals as originating from saidseismic source, ii. discerning the presence or absence of verifiedsignals within recurring time windows, iii. translating a first portionof operative information from the presence or absence of said verifiedsignals; vi. determining the initiation times of said signals; and, vii.translating a second portion of operative information from said [the]initiation times of said signals, and (d) said processor beingprogrammed and equipped to be capable of modifying its operation inaccordance with said operative information.
 38. The apparatus of claim37 wherein said processor is further capable to discern and communicatea relevant portion of said operative information to a proximatecontrollable tool affixed within said drill string.
 39. The apparatus ofclaim 38 in which said tool has capability to receive said relevantportion of said operative information and capabilty to actuate inaccordance with said operative information.
 40. The apparatus of claim38 in which said tool is a logging tool.
 41. The apparatus of claim 38in which said tool is an uphole communication device.
 42. The apparatusof claim 41 in which said uphole communication device is a mud pulsetelemetry transmitter.
 43. The apparatus of claim 37 in which saidprocessor is programmed to determine said first portion of saidoperative information from the number of consecutive time windows inwhich said shots were initiated.
 44. The apparatus as described by claim37 wherein said subterranean processor is further programmed todetermine a first time differential between a predetermined momentrelative to a time window opening and the receipt moment of a verifiedsignal.
 45. The apparatus as described by claim 44 wherein said firsttime differential represents a seismic signal travel time between saidsurface source and said subterranean receiver at the respective signalreceiver position. 46 The apparatus as described by claim 45 whereinsaid apparatus is capable to determine said first time differential at aplurality of signal receiver positions along a length of said borehole.47. The apparatus as described by claim 37 further having the capabilityto continually measure the ambient seismic noise level and to inhibitsaid seismic shots and seismic recording by said subterranean receiverduring periods when ambient seismic noise is above a threshold level.48. The apparatus as described by claim 37 in which said controllableseismic source is programmed to restrict the initiation times of saidseismic shots to times during which said subterranean receiver is withina predetermined depth range.
 49. The apparatus of claim 48 wherein saidsubterranean processor is further programmed to monitor boreholetemperature sensed by a linked thermal sensor to determine current depthand further programmed to acquire seismic data only during apredetermined depth range indicated by borehole temperature.
 50. Theapparatus of claim 48 wherein said subterranean processor is furtherprogrammed to monitor borehole pressure sensed by a linked pressuresensor and is further programmed to acquire seismic data only during apredetermined depth range indicated by borehole pressure. 51 Theapparatus as described by claim 37 wherein said seismic signal sourcecomprises a signal controller having a first clock and wherein saidsubterranean processor includes a second clock, said subterraneanprocessor programmed to determine a first time differential between apredetermined moment relative to a time window opening and the receiptmoment of a verified signal.
 52. The apparatus as described by claim 51wherein said determined first time differential represents a seismicsignal travel time between said surface source and said subterraneanreceiver at the respective signal receiver position.
 53. The apparatusas described by claim 52 having the capability to determine said firsttime differential at a plurality of signal receiver positions along alength of said borehole. 54 The apparatus as described by claim 53further programmed to process said first time differentials respectiveto said plurality of receiver positions along said borehole to compute[image geologic characteristics between said seismic signal source andsaid signal receiver. 55 The apparatus as described by claim 51 whereinsaid subterranean processor is programmed to determine a second timedifferential between the first time differential of subsequent shotscompared to the first time differential of earlier shots and to use saidsecond time differential to synchronize said second clock with saidfirst clock. 56 The apparatus as described by claim 55 wherein verifiedsignals respective to said earlier shots and said subsequent shots maybe received at substantially the same position within said borehole. 57.The apparatus as described by claim 56 having the programmed capabilityto utilize said verified signals from said subsequent shots tosynchronize said second clock to said first clock and the furthercapability to utilize said selfsame verified signals to compute geologiccharacteristics.
 58. The apparatus as described in claim 57 stillfurther having the programmed capability to utilize said verifiedsignals from said subsequent shots to cause actuation of said tool. 59.The apparatus as described in claim 37 wherein surface manipulation ofdrilling processes provides supplementary signals to said subterraneansignal receiver and said subterranean processor has a further programmedcapability to combine said supplementary signals, together with saidseismic signals from said seismic shots, to determine a third portion ofoperative information to said processor, said processor having thefurther capacity to modify its operation in accordance with said first,said second, and said third portions of operative information.
 60. Theapparatus of claim 59 in which said processor is programmed to be ableto determine that a portion of said operative information is for anassociated underground controllable tool and to communicate said portionof said operative information to said tool.
 61. The apparatus of claim60 in which said tool is capable to receive said portion of saidoperative information and to actuate in accordance with said operativeinformation.
 62. The apparatus of claim 60 in which said associatedunderground controllable tool is a logging tool.
 63. The apparatus ofclaim 60 in which said associated underground controllable tool is anuphole communication device.
 64. The apparatus of claim 63 in which saiduphole communication device is a mud pulse telemetry transmitter. 65.The apparatus of claim 59 in which said surface manipulation of drillingprocesses includes sequential pumping variations to cause sequentialborehole pressure variations that convey said third portion of operativeinformation.
 66. The apparatus of claim 59 in which said surfacemanipulation of drilling processes includes sequential pumpingvariations to cause sequential borehole fluid flow variations thatconvey said third portion of operative information. 67 The apparatus ofclaim 59 in which said surface manipulation of drilling processesincludes sequential drill bit motion to cause sequential seismic energyvariations that convey said third portion of operative information. 68.A while-drilling vertical seismic profiling system suitable tocommunicate information to an underground location, comprising: aseismic source to transmit information to said underground location bygeneration of a series of seismic shots at selected times, a seismicreceiver conveyed to said underground location to receive said series ofseismic shots; an underground processor in communication with saidseismic receiver, said processor determining shot initiation times ofdetected shots and presence or absence of a shot initiated at apotential shot initiation time; said processor determining a portion ofsaid information from said determined initiation times; and, saidprocessor determining another portion of said information from saidpresence or absence of said shot.
 69. A while-drilling vertical seismicprofiling system according to claim 68 that also utilizes subsurfacesignals generated by manipulation of the surface-controllable drillingprocesses for communication of information to said seismic receiver. 70.A while-drilling vertical seismic profiling system according to claim 68wherein said seismic receiver is linked to controllable logging toolsand in which said logging tools are controlled at least in part by aportion of said information.
 71. A while-drilling vertical seismicprofiling system according to claim 70 further comprising a telemetrytransmitter that is controlled at least in part by said information andmay be utilized to transmit data provided by said logging tools and saidseismic receiver to an uphole or surface receiver.